2.
Tribal Contact:
Christopher Lee
Air Program Manager - Southern Ute Indian Tribe
970-563-4705
2. Description of Permit Amendment
On November 8, 2007, EPA sent a letter to inform you of a new mailing address,
effective December 17, 2007, for the submittal of annual fee payments required pursuant to 40
CFR Part 71 and the title V permits issued by EPA’s Office of Air and Radiation. The operating
permit for Treating Site #2 Compressor Station is being re-opened and administratively amended
pursuant to 40 CFR 71.7(f) to correct the fee payment address in the permit. The new addresses
are as follows:
For regular U.S. postal service mail For non-U.S. postal service express mail
(FedEx, Airborne, DHL, and UPS)
U.S. Environmental Protection Agency U.S. Bank
FOIA and Miscellaneous Payments Government Lockbox 979078
Cincinnati Finance Center U.S. EPA FOIA & Misc. Payments
P.O. Box 979078 1005 Convention Plaza
St. Louis, MO 63197-9000 SL-MO-C2-GL
St. Louis, MO 63101
In an effort to streamline the title V permits and reduce the number of administrative
permit amendments requested, EPA is removing specific non-enforceable facility information,
such as the names and phone numbers of the Responsible Official, Alternate Responsible
Official, Facility Contact, and Tribal Contact. Part 71 does not require this information to be in
the permit and changes to such information are the most often requested administrative permit
amendments. This information will be maintained in the Statements of Basis for each permit
action. EPA requests from this point forward that BP America Production Company continue to
send notification in writing of changes to such facility information; however, the changes will no
longer require administrative permit amendments. The notifications will be kept on file, similar
to Off Permit Change notifications, and the most current information will be updated in the
Statement of Basis as part of the next permit modification or renewal. In addition, EPA has
revised the text for Alternative Operating Scenarios and Off Permit Changes for clarification
purposes. EPA also reviewed the records for Off Permit Changes notifications for the facility
and has updated serial numbers for emission units that have been replaced or overhauled.
On December 3, 2007, the EPA received a letter from BP requesting clarification of the
periodic monitoring requirements text in permit condition II.D.3. The changes requested were
not directly related to emissions and will not change the enforceability of the monitoring
requirements. The operating permit for Treating Site #2 Compressor Station has been
administratively amended to incorporate the requested changes to permit condition II.D.3.
2

3.
The following modifications have been made to this permit:
• Permit number and issue/effective/expiration dates removed from signature cover
page.
• Permit issuance cover page created to follow signature cover page (includes
information removed from signature cover page).
• Section I.A. Source Information
1. Names and phone numbers for the Responsible Official, Alternate
Responsible Official, Company Contact and Tribal Contact were removed.
Parent Company Mailing Address was removed.
• Section I.B. Source Emission Points, Table 1- Source Emission Points
1. Serial numbers for emission units were updated based on Off Permit Change
notifications.
• Section II.D.3 Monitoring Requirements
1. Clarification to the periodic monitoring requirements for engines that run less
than half of the quarter.
• Section III.C. Alternative Operating Scenario- Engine Replacement/Overhaul for
Non-PSD Permitted Engines
1. Text was revised for clarification purposes.
• Section III.Q. Off Permit Changes
1. Text was revised for clarification purposes.
• Section IV.A. Annual Fee Payment
1. Bank name and address for submittal of annual fee payments was changed.
• Section V.A. Permit Revision History
1. Permit revision history was changed and has been removed from the Appendix
and moved to the permit issuance cover page at the front of the permit.
In accordance with the requirements of permit condition IV.H. and 40 CFR 71.7(d), EPA
is making these revisions as an administrative amendment to the permit. The permit will be
reissued as permit number V-SU-0002-05.01.
For specific applicability information regarding the part 71 permit for this facility, please
see the Statement of Basis for permit number V-SU-0002-05.00.
3 Printed on Recycled Paper

5.
c. Description of operations
Treating Site #2 Compressor Station is a central facility used to treat the gas and water
recovered from the coal matrix reservoirs of the San Juan Basin located in Area #2 of the Ignacio
Blanco Fruitland field. Coal bed methane gas wells are produced similarly to conventional gas
wells, but with a larger quantity of associate water production. After leaving the well, the
production is sent to a wellsite separator which splits the stream into separate gas and water
gathering lines prior to entering the treating facility.
The gas enters the facility at about 45 psi and passes through a slug catcher used for water
and gas separation. The water that drops out combines with the produced water stream from the
field and is stored in water tanks. Each water tank has a tank heater used during the winter
months to heat the water. The produced water is pumped from the tanks through water injection
pumps and re-injected into a deep reservoir for disposal. After leaving the slug catcher, the
produced gas is compressed to about 390 psi before passing through a glycol dehydrator unit
equipped with a natural gas fired reboiler to further dry the gas. After dehydration, most of the
gas is sent through a custody transfer sales meter to Red Cedar Gathering, while some of the gas
is returned to the field to be used as wellsite fuel gas. The gas contains only a negligible amount
of hydrogen sulfide (H2S). Therefore, no H2S removal is necessary. It should be noted that these
wells do not produce any condensate or natural gas liquids and VOC content of the gas is only
0.05% by weight. Current production at this facility is about 18 MMscfd.
d. Permitting history
Treating Site #2 commenced operation in 1990. On July 31, 1997, EPA issued a PSD
permit for the facility. That PSD permit was revised on June 9, 1999. EPA issued the initial part
71 permit, # V-SU-0002-00.00, on March 27, 2000. That permit will be replaced by this renewal
permit, # V-SU-0002-05.00.
e. List of all units and emission-generating activities
BP America Production Company provided in their applications the information
contained in Tables 1 and 2 for this facility. Table 1 lists emission units and emission generating
activities, including any air pollution control devices. Emission units identified as “insignificant”
are listed separately in Table 2.
2

8.
f. Potential to emit
Potential to emit means the maximum capacity of Treating Site #2 to emit any air
pollutant under its physical and operational design. Any physical or operational limitation on the
capacity of Treating Site #2 to emit an air pollutant, including air pollution control equipment
and restrictions on hours of operation or on the type or amount of material combusted, stored, or
processed, may be treated as part of its design if the limitation is enforceable by EPA. Potential
to emit is meant to be a worse case emissions calculation. Actual emissions may be much lower.
The potential to emit for the facility as a whole are as follows:
Nitrogen Oxides (NOx) – 59.4 tpy
Carbon Monoxide (CO) – 86.2 tpy
Volatile Organic Compounds (VOC) – 38.7 tpy
Small Particulates (PM10) – 2.6 tpy
Sulfur Dioxide (SO2) - 0.08 tpy
Total Hazardous Air Pollutants (HAPs) –5.38 tpy
Largest Single HAP (formaldehyde, HCHO) – 5.38 tpy
5

9.
2. Tribe Information
a. Indian country
The BP Treating Site #2 Compressor Station is located within the exterior boundaries of
the Southern Ute Indian Reservation and is thus within Indian country as defined at 18 U.S.C.
'1151. The Southern Ute Tribe does not have a federally-approved Clean Air Act (CAA) title V
operating permits program nor does EPA’s approval of the State of Colorado’s title V program
extend to Indian country. Thus, EPA is the appropriate governmental entity to issue the title V
permit to this facility.
b. The reservation
The Southern Ute Indian Reservation is located in Southwestern Colorado adjacent to the
New Mexico boundary. Ignacio is the headquarters of the Southern Ute Tribe, and Durango is
the closest major city, just 5 miles outside of the north boundary of the Reservation. Current
information indicates that the population of the Tribe is about 1,305 people with approximately
410 tribal members living off the Reservation. In addition to Tribal members, there are over
30,000 non-Indians living within the exterior boundaries of the Southern Ute Reservation.
c. Tribal government
The Southern Ute Indian Tribe is governed by the Constitution of the Southern Ute Indian
Tribe of the Southern Ute Indian Reservation, Colorado adopted on November 4, 1936 and
subsequently amended and approved on October 1, 1975. The Southern Ute Indian Tribe is a
federally recognized Tribe pursuant to Section 16 of the Indian Reorganization Act of June 18,
1934 (48 Stat.984), as amended by the Act of June 15, 1935 (49 Stat. 378). The governing body
of the Southern Ute Indian Tribe is a seven member Tribal Council, with its members elected
from the general membership of the Tribe through a yearly election process. Terms of the Tribal
Council are three years and are staggered so in any given year 2 members are up for reelection.
The Tribal Council officers consist of a Chairman, Vice-Chairman and Treasurer.
d. Local air quality and attainment status
The Tribe maintains an air monitoring network consisting of two sites equipped to collect
Oxides of Nitrogen (NO2), Ozone (O3), Carbon Monoxide (CO) and meteorological data. The
Tribe has collected NO2 and O3 data at the Ignacio site and Bondad site since June 1, 1982, and
April 1, 1997, respectively. Since January 1, 2000, both sites initiated meteorological monitors
measuring Wind Speed, Wind Direction, Vertical Wind Speed, Outdoor Temperature, Relative
Humidity, Solar Radiation, and Rain/Snow Melt Precipitation. Particulate data (PM10) was
collected from December 1, 1981 to September 30, 2006, at the Ignacio site and since April 1,
1997 to September 30, 2006, at the Bondad site. The monitors indicate the following averages for
the pollutant monitored: An annual average for NO2, an hourly average for O3 and CO, an 8-hour
average for CO.
6

10.
3. Applicable Requirements
a. Applicable Requirement Review
The following discussions address applicable requirements, and requirements that may
appear to be applicable but are not. All applicable and non-applicable requirements addressed
here are included in the Code of Federal Regulations, Title 40.
Prevention of Significant Deterioration (PSD)
PSD applies to the BP Treating Site #2 Compressor Station. The original construction of
the site, in 1990, triggered PSD Review. BP was issued a PSD permit for Treating Site #2 on
July 31, 1997. The PSD permit was revised on June 9, 1999. The PSD permits requires that the
subject engines meet a BACT limit for NOx of 1.0 g/hp-hr and a limit for CO of 2.0 g/hp-hr.
These BACT limits were accomplished by retrofitting the engines with non-selective catalytic
reduction (NSCR) and air/fuel controllers.
PSD Monitoring, Recordkeeping, and Reporting
In addition to the BACT limits, the PSD permit requires quarterly and semi-annual NOx
and CO monitoring for controlled and uncontrolled engines, respectively. Portable analyzers
were proposed by BP for conducting the monitoring. The PSD permit also requires that BP keep
records of its monitoring and maintenance information and that these records be kept for a period
of 5 years. Monitoring data must be reported to EPA semi-annually.
Periodic Monitoring
Some monitoring was required in the PSD permit for determining compliance with the
NOx and CO engine emission limits. The PSD permit allowed BP to reduce the frequency of
monitoring from quarterly to semi-annually after BP had demonstrated compliance with the
engine emission limits for six (6) consecutive quarters. To enhance periodic monitoring for the
controlled engines, BP will conduct additional monitoring and maintenance activities on the
controlled engines at least once every quarter. These additional requirements are:
1) Measure exhaust back pressure;
2) Measure differential pressure and temperature across the catalytic converter;
3) Replace oxygen sensors;
4) Inspect and lubricate air/fuel ratio control valves; and
5) Measure concentrations of CO and NOx in exhaust.
7

11.
Chemical Accident Prevention Program
Based on BP’s application, Treating Site #2 currently has no regulated substances above the
threshold quantities in this rule and therefore are not subject to the requirement to develop and submit a
risk management plan. BP has an ongoing responsibility to submit this plan IF a substance is listed
that BP has in quantities over the threshold amount or IF BP ever increases the amount of any regulated
substance above the threshold quantity.
Stratospheric Ozone and Climate Protection
Based on its applications, BP does not currently engage in the activities regulated under this
provision. However, should BP perform any maintenance, service, repair, or disposal, of any
equipment containing chlorofluorocarbons (CFCs), or contract with someone to do this work at
Treating Site #2, BP would be required to comply with Title VI of the Clean Air Act and submit an
application for a modification to any Title V operating permit of a subject treating site.
New Source Performance Standards (NSPS)
40 CFR Part 60, Subpart A: General Provisions. This subpart applies to the owner or operator
of any stationary source which contains an affected facility, the construction or modification of which
is commenced after the date of publication of any standard in part 60. The general provisions under
subpart A apply to sources that are subject to the specific subparts of part 60.
As explained below, the Treating Site #2 Compressor Station is not subject to any specific
subparts of part 60, therefore the General Provisions of part 60 do not apply.
40 CFR Part 60, Subpart K: Standards of Performance for Storage Vessels for Petroleum
Liquids for which Construction, Reconstruction, or Modification Commenced After June 11, 1973, and
Prior to May 19, 1978. This rule applies to storage vessels for petroleum liquids with a storage
capacity greater than 40,000 gallons. 40 CFR part 60, subpart K does not apply to storage vessels for
petroleum or condensate stored, processed, and/or treated at a drilling and production facility prior to
custody transfer.
The subpart does not apply to the storage vessels at the Treating Site #2 Compressor Station
because there are no tanks at this site that were constructed, reconstructed, or modified after June 11,
1973, and prior to May 19, 1978.
40 CFR Part 60, Subpart Ka: Standards of Performance for Storage Vessels for Petroleum
Liquids for which Construction, Reconstruction, or Modification Commenced After May 18, 1978, and
Prior to June 23, 1984. This rule applies to storage vessels for petroleum liquids with a storage
capacity greater than 40,000 gallons. Subpart Ka does not apply to petroleum storage vessels with a
capacity of less than 420,000 gallons used for petroleum or condensate stored, processed, or treated
prior to custody transfer.
8

12.
This subpart does not apply to the storage vessels at the Treating Site #2 Compressor Station
because there are no tanks at this site that were constructed, reconstructed, or modified after May 18,
1978, and prior to June 23, 1984.
40 CFR Part 60, Subpart Kb: Standards of Performance for Volatile Organic Liquid Storage
Vessels (Including Petroleum Liquid Storage Vessels) for which Construction, Reconstruction, or
Modification Commenced After July 23, 1984. This rule applies to storage vessels with a capacity
greater than or equal to 75 cubic meters storing volatile organic liquids.
This subpart does not apply to the storage vessels at the Treating Site #2 Compressor Station
because the facility has no tanks greater than or equal to 75 cubic meters that store volatile organic
liquids.
40 CFR Part 60, Subpart GG: Standards of Performance for Stationary Gas Turbines. This rule
applies to stationary gas turbines, with a heat input at peak load equal to or greater than 10.7 gigajoules
per hour (10 MMBtu/hr), that commenced construction, modification, or reconstruction after October
3, 1977.
There are no stationary gas turbines located at the Treating Site #2 Compressor Station,
therefore this subpart does not apply.
40 CFR Part 60, Subpart KKK: Standards of Performance for Equipment Leaks of VOC from
Onshore Natural Gas Processing Plants. This rule applies to compressors and other equipment at
onshore natural gas processing facilities. As defined in this subpart, a natural gas processing plant is
any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of
mixed natural gas liquids (NGLs) to natural gas products, or both. Natural gas liquids are defined as
the hydrocarbons, such as ethane, propane, butane, and pentane that are extracted from field gas.
The Treating Site #2 Compressor Station does not extract natural gas liquids from field gas, nor
does it fractionate mixed NGLs to natural gas products, and thus does not meet the definition of a
natural gas processing plant under this subpart. Therefore, this rule does not apply.
40 CFR Part 60, Subpart LLL: Standards of Performance for Onshore Natural Gas Processing;
SO2 Emissions. This rule applies to sweetening units and sulfur recovery units at onshore natural gas
processing facilities. As defined in this subpart, sweetening units are process devices that separate
hydrogen sulfide (H2S) and carbon dioxide (CO2) from a sour natural gas stream. Sulfur recovery units
are defined as process devices that recover sulfur from the acid gas (consisting of H2S and CO2)
removed by a sweetening unit.
The Treating Site #2 Compressor Station does not perform sweetening or sulfur recovery at the
facility. Therefore, this subpart does not apply.
40 CFR Part 60, Subpart KKKK: Standards of Performance for Stationary Combustion
Turbines. This subpart establishes emission standards and compliance schedules for the control of
emissions from stationary combustion turbines that commenced construction, modification or
reconstruction after February 18, 2005. The rule applies to stationary combustion turbines with a heat
input at peak load equal to or greater than 10.7 gigajoules per hour (10 MMBtu/hr).
9

13.
BP does not operate stationary combustion turbines at the Treating Site #2 Compressor Station.
Therefore, this subpart does not apply.
National Emissions Standards for Hazardous Air Pollutants (NESHAP)
40 CFR Part 63, Subpart A: General Provisions. This subpart contains national emissions
standards for hazardous air pollutants (HAP) that regulate specific categories of sources that emit one
or more HAP regulated pollutants under the Clean Air Act. The general provisions under subpart A
apply to sources that are subject to the specific subparts of part 63.
Treating Site #2 Compressor Station is not subject to any specific subparts of part 63, therefore
the General Provisions of part 63 do not apply.
40 CFR Part 63, Subpart HH: National Emission Standards for Hazardous Air Pollutants from
Oil and Natural Gas Production Facilities. This subpart applies to the owners and operators of affected
units located at natural gas production facilities that are major sources of HAP’s, and that process,
upgrade, or store natural gas prior to the point of custody transfer, or that process, upgrade, or store
natural gas prior to the point at which natural gas enters the natural gas transmission and storage source
category or is delivered to a final end user. The affected units are glycol dehydration units, storage
vessels with the potential for flash emissions, and the group of ancillary equipment, and compressors
intended to operate in volatile hazardous air pollutant service, which are located at natural gas
processing plants.
Throughput Exemption:
Those sources whose maximum natural gas throughput, as appropriately calculated in
§63.760(a)(1)(i) through (a)(1)(iii), is less than 18,400 standard cubic meters per day are exempt from
the requirements of this subpart.
Source Aggregation:
Major source, as used in this subpart, has the same meaning as in §63.2, except that:
1.) Emissions from any oil and gas production well with its associated equipment and emissions
from any pipeline compressor station or pump station shall not be aggregated with emissions
from other similar units.
2.) Emissions from processes, operations, or equipment that are not part of the same facility shall
not be aggregated.
3.) For facilities that are production field facilities, only HAP emissions from glycol dehydration
units and storage tanks with flash emission potential shall be aggregated for a major source
determination.
10

14.
Facility:
For the purpose of a major source determination, facility means oil and natural gas production
and processing equipment that is located within the boundaries of an individual surface site as defined
in subpart HH. Examples of facilities in the oil and natural gas production category include, but are not
limited to: well sites, satellite tank batteries, central tank batteries, a compressor station that transports
natural gas to a natural gas processing plant, and natural gas processing plants.
Production Field Facility:
Production field facilities are those located prior to the point of custody transfer. The definition
of custody transfer (40 CFR 63.761) means the point of transfer after the processing/treating in the
producing operation, except for the case of a natural gas processing plant, in which case the point of
custody transfer is the inlet to the plant.
Natural Gas Processing Plant:
A natural gas processing plant is defined in 40 CFR 63.761 as any processing site engaged in
the extraction of NGL’s from field gas, or the fractionation of mixed NGL’s to natural gas products, or
a combination of both. A treating plant or gas plant that does not engage in these activities are
considered to be production field facilities.
Major Source Determination for Production Field Facilities:
The definition of major source in this subpart (at 40 CFR 63.761) states, in part, that only
emissions from the dehydration units and storage vessels with a potential for flash emissions at
production field facilities are to be aggregated when comparing to the major source thresholds. For
facilities that are not production field facilities, HAP emissions from all HAP emission units shall be
aggregated.
Area Source Applicability:
40 CFR part 63, subpart HH applies to area sources of HAPs. An area source is a HAP source
whose total HAP emissions are less than 10 tpy of any single HAP or 25 tpy for all HAPs in aggregate.
This subpart requires different emission reduction requirements for triethylene glycol dehydration
units found at oil and gas production facilities based on their geographical location. Units located in
densely populated areas (determined by the Bureau of Census) and known as urbanized areas with an
added 2-mile offset and urban clusters of 10,000 people or more, are required to have emission
controls. Units located outside these areas will be required to have the glycol circulation pump rate
optimized or operators can document that PTE of benzene is less than 1 tpy.
Applicability of subpart HH to the Treating Site #2 Compressor Station:
The Treating Site #2 Compressor Station does not engage in the extraction of NGL’s and
therefore is not considered a natural gas processing plant. Hence, the point of custody transfer, as
defined in this subpart HH, occurs downstream of the station and the facility would therefore be
11

15.
considered a production field facility. For production field facilities, only emissions from the
dehydration units and storage vessels with a potential for flash emissions are to be aggregated to
determine major source status. The facility does not have flash tanks and the HAP emissions from the
dehydration units alone at the facility are below the major source thresholds of 10 tons per year of a
single HAP and 25 tons per year of aggregated HAP’s.
With respect to the area source requirements of this subpart, the facility is located outside both
an urban area and an urban cluster. Furthermore, uncontrolled benzene emissions from each of the
TEG units at the facility were determined to be less than 1 tpy using GRI-GLYCalc Version 4.0, as
presented in the supporting documentation in the application. As a result, each dehydration unit at
the facility is exempt from the §67.764(d) general requirements for area sources. However, the
following general recordkeeping requirement does apply to this facility:
o §63.774(d)(1) – retain the GRI-GLYCalc determinations used to demonstrate that actual
average benzene emissions are below 1 tpy.
40 CFR Part 63, Subpart HHH: National Emission Standards for Hazardous Air Pollutants
from Natural Gas Transmission and Storage Facilities. This rule applies to natural gas transmission
and storage facilities that transport or store natural gas prior to entering the pipeline to a local
distribution company or to a final end user, and that are a major source of hazardous air pollutant
(HAP) emissions. Natural gas transmission means the pipelines used for long distance transport and
storage vessel is a tank or other vessel designed to contain an accumulation of crude oil, condensate,
intermediate hydrocarbon, liquids, produced water or other liquid and is constructed of wood, concrete,
steel or plastic structural support.
This subpart does not apply to the Treating Site #2 Compressor Station as the facility is a
natural gas production facility and not a natural gas transmission or storage facility.
40 CFR Part 63, Subpart ZZZZ: National Emission Standards for Hazardous Air Pollutants for
Stationary Reciprocating Internal Combustion Engines. This rule establishes national emission
limitations and operating limitations for HAPs emitted from stationary reciprocating internal
combustion engines (RICE). A stationary RICE is any internal combustion engine which uses
reciprocating motion to convert heat energy into mechanical work and which is not mobile. This rule
applies to owners or operators of stationary RICE which are located at a major source of HAP, except
if the RICE have a site-rating of 500 brake horse power (bhp) or less. While all stationary RICE with a
site-rating of more than 500 bhp located at major sources are subject to the final rule, there are distinct
requirements for regulated stationary RICE depending on their design, use, and fuel. The standards in
the final rule have specific requirements for all new or reconstructed RICE and for existing spark
ignition 4 stroke rich burn (4SRB) stationary RICE. With the exception of the existing spark ignition
4SRB stationary RICE, other types of existing stationary RICE (i.e., spark ignition 2 stroke lean burn
(2SLB), spark ignition 4 stroke lean burn (4SLB), compression ignition (CI), stationary RICE that
combust landfill or digester gas equivalent to 10 percent or more of the gross heat input on an annual
basis, emergency, and limited use units) located at a major source of HAP emissions are not subject to
any specific requirement under the final rule.
12

16.
A stationary RICE is existing if construction or reconstruction of the unit commenced before
December 19, 2002. A stationary RICE is new if construction of the unit commenced on or after
December 19, 2002. A stationary RICE is reconstructed if the definition of reconstruction in '63.2 is
met and reconstruction commenced on or after December 19, 2002.
This subpart does not apply to the facility, as the HAP emission are below the major source
thresholds.
Compliance Assurance Monitoring (CAM) Rule
The CAM rule applies to each Pollutant Specific Emission Unit (PSEU) that meets a three-part
test. The PSEU must 1) be subject to an emission limitation or standard, and 2) use a control device to
achieve compliance, and 3) have a pre-control emissions that exceed or are equivalent to the major
source threshold.
BP Treating Site #2 is subject to emission limits for NOx and CO for specific compressor
engines. Two engines at the site are subject to a control requirement (BACT) of NSCR and air/fuel
ratio controllers. The engines retrofitted with controls meet the requirements for determining
applicability of CAM for the NOx and CO emissions. However, according to 40 CFR 64.2(b)(1)(vi),
CAM requirements do not apply to any emission unit that is subject to an emission limit or standard for
which an applicable requirement specifies a continuous compliance determination method. The part 71
permits for these controlled engines require demonstrations through quarterly stack gas concentration
monitoring of NOx and CO, parametric monitoring and maintenance activities. Parametric
measurements include exhaust back pressure as well as differential pressure and temperature across the
catalytic converter. The oxygen sensors must be replaced, and air/fuel ratio control valves must be
inspected and lubricated. These existing conditions are sufficient to provide reasonable assurance of
continuous compliance and allow BP to make an informed certification of compliance.
b. Conclusion
Based on the information provided in BP’s application for the Treating Site #2 Compressor
Station, this source is subject to those existing applicable Federal CAA programs discussed above.
The Treating Site #2 Compressor Station is not subject to any implementation plan such as exists
within state jurisdictions. Therefore, the Treating Site #2 Compressor Station is not subject to any
other substantive requirements that control their emissions under the CAA.
EPA recognizes that, in some cases, sources of air pollution located in Indian country are
subject to fewer requirements than similar sources located on land under the jurisdiction of a state or
local air pollution control agency. To address this regulatory gap, EPA is in the process of developing
national regulatory programs for preconstruction review of major sources in non-attainment areas and
of minor sources in both attainment and non-attainment areas. These programs will establish, where
appropriate, control requirements for sources that would be incorporated into part 71 permits. To
establish additional applicable, federally-enforceable emission limits, EPA Regional Offices will, as
necessary and appropriate, promulgate Federal Implementation Plans (FIPs) that will establish Federal
requirements for sources in specific areas. EPA will establish priorities for its direct Federal
implementation activities by addressing as its highest priority the most serious threats to public health
13

17.
and the environment in Indian country that are not otherwise being adequately addressed.
Further, EPA encourages and will work closely with all tribes wishing to develop Tribal
Implementation Plans (TIPs) for approval under the Tribal Authority Rule. EPA intends that its
Federal regulations created through a FIP will apply only in those situations in which a tribe does not
have an approved TIP.
4. EPA Authority
a. General authority to issue part 71 permits
Title V of the Clean Air Act requires that EPA promulgate, administer, and enforce a Federal
operating permits program when a state does not submit an approvable program within the time frame
set by title V or does not adequately administer and enforce its EPA-approved program. On July 1,
1996 (61 FR 34202), EPA adopted regulations codified at 40 CFR part 71 setting forth the procedures
and terms under which the Agency would administer a Federal operating permits program. These
regulations were updated on February 19, 1999 (64 FR 8247) to incorporate EPA's approach for issuing
Federal operating permits to stationary sources in Indian country.
As described in 40 CFR 71.4(a), EPA will implement a part 71 program in areas where a state,
local, or tribal agency has not developed an approved part 70 program. Unlike states, Indian tribes are
not required to develop operating permits programs, though EPA encourages tribes to do so. See, e.g.,
Indian Tribes: Air Quality Planning and Management (63 FR 7253, February 12, 1998) (also known as
the ATribal Authority Rule@). Therefore, within Indian country, EPA will administer and enforce a part
71 Federal operating permits program for stationary sources until a tribe receives approval to
administer their own operating permits program.
5. Use of All Credible Evidence
Determinations of deviations, continuous or intermittent compliance status, or violations of the
permit are not limited to the testing or monitoring methods required by the underlying regulations or
this permit; other credible evidence (including any evidence admissible under the Federal Rules of
Evidence) must be considered by the source and EPA in such determinations.
6. Public Participation
a. Public notice
As described in 40 CFR 71.11(a)(5), all part 71 draft operating permits shall be publicly noticed
and made available for public comment. The Public Notice of permit actions and public comment
period is described in 40 CFR 71(d).
There was a 30 day public comment period for actions pertaining to a draft permit. Public
notice was given for this draft permit by mailing a copy of the notice to the permit applicant, the
affected state, tribal and local air pollution control agencies, the city and county executives, the state
and Federal land managers and the local emergency planning authorities which have jurisdiction over
the area where the source is located. A copy of the notice was provided to all persons who have
14

18.
submitted a written request to be included on the mailing list. If you would like to be added to our
mailing list to be informed of future actions on these or other Clean Air Act permits issued in Indian
country, please send your name and address to the contact listed below:
Kathleen Paser, Part 71 Permit Contact
U.S. Environmental Protection Agency, Region 8
1595 Wynkoop Street (8P-AR)
Denver, Colorado 80202
Public notice was published in the Durango Herald on July 20, 2007, giving opportunity for
public comment on the draft permit and the opportunity to request a public hearing.
b. Opportunity for Comment
Members of the public were given an opportunity to review a copy of the draft permit prepared
by EPA, the application, this statement of basis for the draft permit, and all supporting materials for the
draft permit. Copies of these documents were available at:
La Plata County Clerk=s Office
1060 East 2nd Avenue
Durango, Colorado 81302
and
Southern Ute Indian Tribe
Environmental Programs Office
116 Mouache Drive
Ignacio, Colorado 81137
and
US EPA Region 8
Air and Radiation Program Office
1595 Wynkoop Street (8P-AR)
Denver, Colorado 80202
All documents are available for review at the U.S. EPA Region 8 office Monday through
Friday from 8:00 a.m. to 4:00 p.m. (excluding Federal holidays).
Any interested person may submit written comments on the draft part 71 operating permit
during the public comment period to the Part 71 Permit Contact at the address listed above. All
comments will be considered and answered by EPA in making the final decision on the permit.
EPA keeps a record of the commenters and of the issues raised during the public participation
process.
Anyone, including the applicant, who believes any condition of the draft permit is
inappropriate should raise all reasonable ascertainable issues and submitted all arguments
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supporting their position by the close of the public comment period. Any supporting materials
submitted must be included in full and may not be incorporated by reference, unless the material
has been already submitted as part of the administrative record in the same proceeding or consists
of state or Federal statutes and regulations, EPA documents of general applicability, or other
generally available reference material.
c. Opportunity to Request a Hearing
A person may submit a written request for a public hearing to the Part 71 Permit Contact,
at the address listed above, by stating the nature of the issues to be raised at the public hearing.
Based on the number of hearing requests received, EPA will hold a public hearing whenever it
finds there is a significant degree of public interest in a draft operating permit. EPA will provide
public notice of the public hearing. If a public hearing is held, any person may submit oral or
written statements and data concerning the draft permit.
d. Appeal of permits
Within 30 days after the issuance of a final permit decision, any person who filed
comments on the draft permit or participated in the public hearing may petition to the
Environmental Appeals Board to review any condition of the permit decision. Any person who
failed to file comments or participate in the public hearing may petition for administrative
review, only if the changes from the draft to the final permit decision or other new grounds were
not reasonably foreseeable during the public comment period. The 30 day period to appeal a
permit begins with EPA=s service of the notice of the final permit decision.
The petition to appeal a permit must include a statement of the reasons supporting the
review, a demonstration that any issues were raised during the public comment period, a
demonstration that it was impracticable to raise the objections within the public comment period,
or that the grounds for such objections arose after such a period. When appropriate, the petition
may include a showing that the condition in question is based on a finding of fact or conclusion
of law which is clearly erroneous; or, an exercise of discretion, or an important policy
consideration which the Environmental Appeals Board should review.
The Environmental Appeals Board will issue an order either granting or denying the
petition for review, within a reasonable time following the filing of the petition. Public notice of
the grant of review will establish a briefing schedule for the appeal and state that any interested
person may file an amicus brief. Notice of denial of review will be sent only to the permit
applicant and to the person requesting the review. To the extent review is denied, the conditions
of the final permit decision become final agency action.
A motion to reconsider a final order shall be filed within 10 days after the service of the
final order. Every motion must set forth the matters claimed to have been erroneously decided
and the nature of the alleged errors. Motions for reconsideration shall be directed to the
Administrator rather than the Environmental Appeals Board. A motion for reconsideration shall
not stay the effective date of the final order unless it is specifically ordered by the Board.
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e. Petition to reopen a permit for cause
Any interested person may petition EPA to reopen a permit for cause, and EPA may
commence a permit reopening on its own initiative. EPA will only revise, revoke and reissue, or
terminate a permit for the reasons specified in 40 CFR 71.7(f) or 71.6(a)(6)(i). All requests must
be in writing and must contain facts or reasons supporting the request. If EPA decides the
request is not justified, it will send the requester a brief written response giving a reason for the
decision. Denial of these requests is not subject to public notice, comment, or hearings. Denials
can be informally appealed to the Environmental Appeals Board by a letter briefly setting forth
the relevant facts.
f. Notice to affected states/tribes
As described in 40 CFR 71.11(d)(3)(i), public notice will be given by mailing a copy of
the notice to the air pollution control agencies of affected states, tribal and local air pollution
control agencies which have jurisdiction over the area in which the source is located, the chief
executives of the city and county where the source is located, any comprehensive regional land
use planning agency and any state or Federal land manager whose lands may be affected by
emissions from the source. The following entities were notified:
State of Colorado, Department of Public Health and Environment
State of New Mexico, Environment Department
Southern Ute Indian Tribe, Environmental Programs Office
Ute Mountain Ute Tribe, Environmental Programs
Navajo Tribe, Navajo Nation EPA
Jicarilla Tribe, Environmental Protection Office
La Plata County, County Clerk
Town of Ignacio, Mayor
National Park Service, Air, Denver, CO
U.S. Department of Agriculture, Forest Service, Rocky Mountain Region
Carl Weston
San Juan Citizen Alliance
Rocky Mountain Clean Air Action
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